Systems and Methods for Increasing Carbon Dioxide in Gasification

ABSTRACT

Systems and methods for processing carbonaceous material are provided. In one or more embodiments, a carbonaceous material and water can be mixed to provide a slurried mixture. The water mixed with the carbonaceous material can be at least 90% liquid phase. At least a portion of the slurried mixture can be gasified in the presence of a combustion gas to provide carbonaceous solids and a syngas comprising hydrogen, carbon monoxide, and carbon dioxide. The syngas can be at a temperature of from about 400° C. to about 1,650° C. At least a portion of the carbonaceous solids can be selectively separated from the syngas to provide a syngas product and carbonaceous solids. At least a portion of the separated carbonaceous solids can be combusted in the presence of an oxidant to provide at least a portion of the combustion gas.

BACKGROUND

1. Field

The present embodiments generally relate to the gasification of carbonaceous material. More particularly, the present embodiments relate to increasing carbon dioxide content of gasified carbonaceous material.

2. Description of the Related Art

The gasification of carbonaceous material typically involves reacting carbonaceous material in a gasifier in a reducing (oxygen-starved) atmosphere at high temperature and high pressure. The resulting syngas contains hydrogen, carbon monoxide, and carbon dioxide. Often at least a portion of the carbon monoxide, if not all, is then converted to carbon dioxide and removed before useful products can be recovered.

Carbon monoxide is typically converted to carbon dioxide in one or more carbon dioxide converters, e.g. a high temperature shift converter followed by a low temperature shift converter. These shift converters require chemicals, catalyst, heat, and/or pressure. As such, carbon dioxide converters are expensive to operate and consume large amounts of energy during operation. Furthermore, carbon dioxide converters add to facility space requirements, costs, and require plant resources.

A need exists for more efficient systems and methods for increasing carbon dioxide during the gasification process.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 depicts an illustrative gasifier for gasifying a carbonaceous material according to one or more embodiments described.

FIG. 2 depicts an illustrative gasifier system for gasifying a carbonaceous material according to one or more embodiments described.

FIG. 3 depicts an illustrative gasification system according to one or more embodiments described.

FIG. 4 depicts another illustrative gasification system according to one or more embodiments described.

DETAILED DESCRIPTION

A detailed description will now be provided. Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including equivalents to the various elements or limitations specified in the claims. Depending on the context, all references below to the “invention” may in some cases refer to certain specific embodiments only. In other cases it will be recognized that references to the “invention” will refer to subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions and examples, but the inventions are not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions, when the information in this patent is combined with available information and technology.

Systems and methods for processing carbonaceous material are provided. In one or more embodiments, a carbonaceous material and water can be mixed to provide a slurried mixture. The water mixed with the carbonaceous material can be at least 90% liquid phase. At least a portion of the slurried mixture can be gasified in the presence of a combustion gas to provide carbonaceous solids and a syngas comprising hydrogen, carbon monoxide, and carbon dioxide. The syngas can be at a temperature of from about 400° C. to about 1,650° C. At least a portion of the carbonaceous solids can be selectively separated from the syngas to provide a syngas product and carbonaceous solids. At least a portion of the separated carbonaceous solids can be combusted in the presence of an oxidant to provide at least a portion of the combustion gas.

With reference to the figures, FIG. 1 depicts an illustrative gasifier 100 for gasifying a carbonaceous material according to one or more embodiments. The gasifier 100 can include an oxidation zone 110, a gasification zone 115, a transfer line 120, a separator 130, a product recovery line 135, and a recycle line 140. The oxidation zone 110 and the gasification zone 115 can be arranged in any order, configuration and/or frequency. For example, the oxidation zone 110 and the gasification zone 115 can be vertically disposed relative to one another, with the gasification zone 115 disposed above the oxidation zone 110. In another example, the oxidation zone 110 and the gasification zone 115 can be vertically disposed relative to one another, with the gasification zone 115 disposed below the oxidation zone.

A carbonaceous material via line 102 can be introduced to the gasification zone 115 to provide a syngas. The syngas can include, but is not limited to hydrogen (“H₂”), carbon monoxide (“CO”), and carbon dioxide (“CO₂”). Water can be introduced via line 104 to the carbonaceous material in line 102 to provide a carbonaceous material/water mixture (“slurried mixture”) via line 102. The carbonaceous material can be slurried with water to provide a transportable mixture via one or more pumps (not shown) that can be introduced to the gasification zone 115. In one or more embodiments, the slurried mixture in line 102 can be introduced without lock hoppers or other common solids introduction devices. This can reduce or eliminate the need for pressurized nitrogen or other carrier gases, lock hoppers, and other equipment, plot size, and costs associated therewith. The slurried mixture in line 102 can be introduced continuously, intermittently, at variable flow rates, or any combination thereof to the gasification zone 115. Although not shown, the slurried mixture via line 102 can be introduced to a mixing zone disposed between the oxidation zone 110 and the gasification zone 115.

The slurried mixture introduced via line 102 to the gasification zone 115 can be gasified to provide a syngas via transfer line 120, which can be introduced to the separator 130. In one or more embodiments, the slurried mixture can be gasified in the presence of a combustion gas, solids, a sorbent, or a combination thereof to provide a syngas and carbonaceous solids mixture via line 120. In one or more embodiments, the sorbent can be added to scavenge oxygen at a rate and level sufficient to delay or prevent the oxygen from reaching a concentration that can result in undesirable side reactions with H₂ (e.g. water) from the carbonaceous material within the gasifier 100. In one or more embodiments, the sorbent can be used to dust or coat carbonaceous material particles in the gasifier 100 to reduce the tendency for the particles to agglomerate. Illustrative sorbents can include but are not limited to carbon rich ash, limestone, dolomite, and coke breeze. Residual sulfur released from the feedstock can be captured by native calcium in the feed or by a calcium based sorbent to form calcium sulfide.

In one or more embodiments, at least a portion of the carbonaceous solids and if used sorbents can be separated from the mixture to provide a syngas product via line 135 and carbonaceous solids, sorbents, or both via line 140. In one or more embodiments, at least a portion of the carbonaceous solids can be introduced via line 140 to the oxidation zone 110 to provide at least a portion of the combustion gas introduced to the gasification zone 115. In one or more embodiments, at least a portion of the carbonaceous material in the slurried mixture introduced via line 102 can be deposited onto solids to provide a mixture containing syngas and carbonaceous containing solids. In one or more embodiments, at least a portion of the carbonaceous containing solids can be can be separated from the mixture in the separator 130 to provide a syngas product via line 135 and carbonaceous containing solids via line 140.

In one or more embodiments, at least a portion of the carbonaceous solids and/or the carbonaceous containing solids introduced via line 140 to the oxidation zone 110 can be combusted in the presence of an oxidant introduced via line 108 to provide at least a portion the combustion gas, solids or both. In one or more embodiments, at least a portion of the carbonaceous solids and/or the carbonaceous containing solids can be combusted in the presence of the oxidant introduced via line 108 and steam introduced via line 106 to provide at least a portion of the combustion gas, solids or both. The combustion gas, solids or both can provide heat to the gasification zone 115 to gasify the slurried carbonaceous mixture introduced via line 102.

In one or more embodiments, one or more carbonaceous materials can be introduced to the oxidation zone 110 in addition to the carbonaceous solids and/or the carbonaceous containing solids. In one or more embodiments, one or more hydrocarbons can be introduced to the oxidation zone 110 in addition to the carbonaceous solids, the carbonaceous containing solids, and/or the one or more carbonaceous materials. The combustion of the one or more carbonaceous materials, hydrocarbons, carbonaceous solids, carbonaceous containing solids, or any combination thereof can provide heat to the gasification zone 115 to gasify the slurried carbonaceous mixture introduced via line 102.

The carbon content in the slurried mixture can range from a low of about 30% wt, about 40% wt, or about 50% wt to a high of about 75% wt, about 85% wt, or about 95% wt. The water content of the slurried mixture can range from a low of about 5% wt, about 15% wt, or about 20% wt to a high of about 50% wt, about 60% wt, or about 70% wt. For example, the slurried mixture can include about 30% wt carbonaceous material and about 70% wt water, about 55% wt carbonaceous material and about 45% wt water, about 62% wt carbonaceous material and about 38% wt water, or about 70% wt carbonaceous material and about 30% wt water. In one or more embodiments, the water content of the slurried mixture can be constant or variable.

The type and amount of oxidant and water introduced to the gasifier 100 can influence the composition and physical properties of the syngas provided via line 135 and the downstream products made therefrom. For example, using air as an oxidant can provide a syngas in line 135 with a CO₂ content ranging from a low of about 2% mol, about 3.5% mol, about 7% mol, or about 9% mol to a high of about 10% mol, about 12% mol, about 14% mol, or more. The CO content of the syngas in line 135 can range from a low of about 2.5% mol, about 5% mol, or about 9% mol to a high of about 10% mol, about 14% mol, about 18% mol, or more. The H₂ content of the syngas in line 135 can range from a low of about 11% mol, about 11.5% mol, or about 12% mol to a high of about 12.5% mol, about 13% mol, about 14% mol, or more. The water content of the syngas in line 135 can range from a low of about 10% mol, about 12% mol, or about 14% mol to a high of about 16% mol, about 18% mol, or about 20% mol. The nitrogen content of the syngas in line 135 can range from a low of about 0% mol, about 3% mol, or about 5% mol to a high of about 40% mol, about 44% mol, about 48% mol, or more. In one or more embodiments, using air as an oxidant can provide a syngas that contains less than about 20% mol CO and more than about 8% mol CO₂.

In one or more embodiments, using oxygen or an essentially nitrogen-free oxidant as the oxidant can provide a syngas in line 135 with a CO₂ content ranging from a low of about 15% mol, about 16.5% mol, or about 18% mol to a high of about 18.5% mol, about 20% mol, about 22% mol or more. The CO content of the syngas in line 135 can range from a low of about 16% mol, about 18% mol, or about 20% mol, to a high of about 25% mol, about 28% mol, about 30% mol, or more. The H₂ content of the syngas in line 135 can range from a low of about 20% mol, about 21% mol, or about 22% mol to a high of about 24% mol, about 26% mol, about 28% mol, or more. The water content of the syngas in line 135 can range from a low of about 20% mol, about 22% mol, or about 24% mol to a high of about 25% mol, about 30% mol, about 35% mol, or more. In one or more embodiments, using oxygen or an essentially nitrogen-free oxidant can provide a syngas that contains less than about 40% mol CO and more than about 16% mol CO₂.

The carbonaceous material in line 102 can include, but is not limited to one or more carbon-containing materials whether solid, liquid, gas, or a combination thereof The one or more carbon-containing materials can include but are not limited to coal, coke, petroleum coke, cracked residue, whole crude oil, crude oil, vacuum gas oil, heavy gas oil, residuum, atmospheric tower bottoms, vacuum tower bottoms, distillates, paraffins, aromatic rich material from solvent deasphalting units, aromatic hydrocarbons, asphaltenes, naphthenes, oil shales, oil sands, tars, bitumens, kerogen, waste oils, biomass (e.g., plant and/or animal matter or plant and/or animal derived matter), tar, low ash or no ash polymers, hydrocarbon-based polymeric materials, heavy hydrocarbon sludge and bottoms products from petroleum refineries and petrochemical plants such as hydrocarbon waxes, byproducts derived from manufacturing operations, discarded consumer products, such as carpet and/or plastic automotive parts/components including bumpers and dashboards, recycled plastics such as polypropylene, polyethylene, polystyrene, derivatives thereof, blends thereof, or any combination thereof Accordingly, the process can be useful for accommodating mandates for proper disposal of previously manufactured materials.

The hydrocarbon-based polymeric materials can include, for example, thermoplastics, elastomers, rubbers, including polypropylenes, polyethylenes, polystyrenes, including other polyolefins, homo polymers, copolymers, block copolymers, and blends thereof; polyethylene terephthalate (PET), poly blends, other polyolefins, poly-hydrocarbons containing oxygen, derivatives thereof, blends thereof, and combinations thereof In one or more embodiments, the carbonaceous material and/or the hydrocarbon introduced to the oxidation zone 110 in addition to the carbonaceous solids and/or the carbonaceous containing solids can be or include materials similar to the carbonaceous materials in line 102.

In one or more embodiments, depending on the moisture concentration of the carbonaceous material, for example coal, the carbonaceous material can be dried prior to introduction to the gasifier 100. The carbonaceous material can be pulverized by milling units such as one or more bowl mill and heated to provide a carbonaceous material containing a reduced amount of moisture. For example, the carbonaceous material can be dried to provide a carbonaceous material containing less than about 50% moisture, less than about 30% moisture, less than about 20% moisture, less than about 15% moisture, or less. The carbonaceous material can be heated in the presence of a gas, for example nitrogen.

The water in line 104 can be purified water, process water, partially processed water, dirty water, other refinery water, other refinery waste water, salt water, or mixtures thereof The water in line 104 can include any suitable waste water, such as sour water, black water, slag containing water, ammonia containing water, hydrogen chloride and/or other acid containing water, sodium hydroxide and/or other base containing water, chemical wastewater, refinery water runoff, process water, tar containing water, or any mixture thereof In one or more embodiments, the water can be at a temperature ranging from a low of about 5° C., about 10° C., about 15° C., or about 20° C. to a high of about 70° C., about 80° C., about 90° C., or one or more embodiments, the water can be about 90% liquid phase, about 95% liquid phase, about 99% liquid phase, or about 99.9% liquid phase. The water can range from about 90% liquid phase to about 100% liquid phase, from about 93% liquid phase to about 97% liquid phase, or from about 96% liquid phase to about 99% liquid phase.

The oxidant introduced via line 108 can include, but is not limited to, air, oxygen, essentially oxygen, oxygen-enriched air, mixtures of oxygen and air, mixtures of oxygen and inert gas such as nitrogen and argon, and combinations thereof. As used herein, the term “essentially oxygen” refers to an oxygen feed containing 51% vol oxygen or more. As used herein, the term “oxygen-enriched air” refers to air containing 21% vol oxygen or more. Oxygen-enriched air can be obtained, for example, from cryogenic distillation of air, pressure swing adsorption, membrane separation, or any combination thereof. In one or more embodiments, the oxidant introduced via line 108 can be nitrogen-free or essentially nitrogen-free. By “essentially nitrogen-free,” it is meant that the oxidant in line 108 contains less than about 5% vol nitrogen, less than about 4% vol nitrogen, less than about 3% vol nitrogen, less than about 2% vol nitrogen, or less than about 1% vol nitrogen. In one or more embodiments, the steam via line 104 can be any suitable type of steam, for example low pressure steam, medium pressure steam, high pressure steam, superheated steam, or superheated high pressure steam.

The amount of oxidant introduced via line 108 to the oxidation zone 110 can range from about 1% to about 90% of the stoichiometric oxygen required to oxidize the total amount of carbonaceous materials in the carbonaceous solids and/or the carbonaceous containing solids. The oxygen concentration within the oxidation zone 110 can range from a low of about 1%, about 3%, about 5%, or about 7% to a high of about 30%, about 40%, about 50%, or about 60% of the stoichiometric requirements based on the molar concentration of carbon in the oxidation zone 110. The oxygen concentration within the oxidation zone 108 can range from a low of about 0.5%, about 2%, about 6%, or about 10% to a high of about 60%, about 70%, about 80%, or about 90% of the stoichiometric requirements based on the molar concentration of carbon in the oxidation zone 110.

In one or more embodiments, the slurried mixture introduced via line 102 to the gasification zone 115 can be heated to a temperature of about 400° C. or more, about 550° C. or more, about 750° C. or more, about 1,000° C. or more, about 1,250° C. or more, about 1,400° C. or more, or about 1,650° C. or more. For example, the slurried mixture introduced via line 102 to the gasification zone 115 can be heated to a temperature ranging from about 900° C. to about 1,065° C., or from about 930° C. to about 1,035° C., or from about 970° C. to about 1,000° C. In one or more embodiments, the combustion gas and solids provided via the oxidation zone 110 can provide all or a portion of the heat required to gasify the slurried mixture introduced via line 102 to the gasification zone 115. In one or more embodiments, additional heat can be introduced to the gasification zone 115 via the introduction of additional combustion gases, steam, heated gases, heating via externally applied heat, or any combination thereof.

In one or more embodiments, the gasifier 100, which can include the oxidation zone 110, the gasification zone 115, the transfer line 120, the separator 130, and recycle line 140 can be operated at a pressure ranging from a low of about 101 kPa, about 300 kPa, or about 600 kPa to a high of about 2,500 kPa, about 3,500 kPa, about 4,500 kPa or more. In one or more embodiments, the pressure of one zone versus another zone, for example the oxidation zone versus the gasification zone can be the same or different. For example, the oxidation zone 110 can be operated at a first pressure and the gasification zone 115 can be operated at a second pressure and the second pressure can be less than, the same, or more than the first pressure.

The residence time of the carbonaceous material introduced via line 102 to the gasification zone 115 can range from about 1 millisecond (“ms”) to about 15 seconds (“s”). The residence time of the slurried mixture introduced via line 102 to the gasification zone 115 can range from a low of about 50 ms, about 100 ms, about 150 ms, or about 200 ms to a high of about 1 s, about 5 s, about 10 s, or about 12 s. The residence time of the slurried mixture introduced via line 102 to the gasification zone 115 can be controlled or otherwise adjusted by introducing the carbonaceous material further downstream from the oxidation zone 110. For example, introducing the carbonaceous material just downstream the oxidation zone 110 will provide a longer residence time than introducing the carbonaceous material to the transfer line 120. Although not shown, a portion or all of the slurried mixture can be introduced at one or more positions within the gasification zone 115 and/or transfer line 120, for example the middle of the gasification zone 115. Introducing the slurried mixture at two or more locations within the gasification zone 115 and/or transfer line 120 can adjust or otherwise modify the syngas provided via line 135. For example, introducing a portion of the slurried mixture via line 102 to the transfer line 120 can provide a shorter residence time, which can vaporize or crack a portion of the carbonaceous materials to provide a syngas in line 135 that can include light hydrocarbons ranging from C₁ to about C₂₀ hydrocarbons.

In one or more embodiments, the temperature of the separated syngas in line 135 can range from a low of about 400° C., about 500° C., about 600° C., or about 700° C. to a high of about 1,200° C., about 1,500° C., about 1,600° C., or about 1,650° C. The pressure of the syngas in line 135 can range from a low of about 101 kPa, about 200 kPa, or about 300 kPa to a high of about 6,975 kPa, about 8,350 kPa, or about 10,400 kPa.

In one or more embodiments, the solids can be, but are not limited to refractory oxides, such as alumina, alpha alumina, zirconia, titania, hafnia, silica, or mixtures thereof, rare earth modified refractory metal oxides, where the rare earth may be any rare earth metal (e.g. lanthanum or yttrium); alkali earth metal modified refractory oxides; ash; derivatives thereof, or mixtures thereof. The solids can be categorized as materials having a substantially stable surface area at reaction conditions, for example, a surface area that is not substantially reactive at the operating conditions, e.g. temperature and pressure.

Although not shown, the carbonaceous containing solids in line 140 can be stripped to remove entrained volatile hydrocarbons. For example, the carbonaceous containing solids can be steam stripped, heat stripped, or stripped using other suitable methods to remove at least a portion of any entrained volatile hydrocarbons. Entrained volatile hydrocarbons can include, for example C₁-C₁₂ hydrocarbons.

In one or more embodiments, the one or more gasifiers 100 can include any gasifier known in the art suitable for gasification of one or more carbonaceous materials. In addition to the oxidation zone 110 and gasification zone 115 previously discussed, the gasifier 100 can include an intermediate reduction zone disposed between the oxidation and gasification zones. In one or more embodiments, the gasifier 100 can include one or more types of gasifiers, including, but not limited to, updraft, downdraft, counter-current, co-current, cross-draft, fluidized bed, double-fired, transport, entrained bed and molten-bath type gasifiers. In one or more embodiments, the gasifier 100 can incorporate one or more efficiency improvement features, including, but not limited to, plug flow, rapid-mix multi-port feed injection, cooled walls, heated walls, or any combination of technologies to enhance gasification efficiency.

In one or more embodiments, the one or more separators 130 can include any system, device, or combination of systems and/or devices capable of providing an outlet particulate concentration less than about 10,000 ppmw, less than about 1,000 ppmw, less than about 500 ppmw, less than about 250 ppmw, less than about 100 ppmw, less than about 50 ppmw, less than about 10 ppmw, less than about 1 ppmw, or less than about 0.1 ppmw. In one or more embodiments, the one or more separators 130 can include one or more cyclonic and/or gravity separators arranged in series, in parallel, or combinations thereof. In one or more embodiments, the one or more separators 130 can include one or more high throughput, low efficiency and/or high efficiency cyclonic separators. In one or more embodiments, the separators 130 can include one or more particulate control devices (“PCDs”). Illustrative PCDs can include, but are not limited to, electrostatic precipitators, sintered metal filters, metal filter candles, and/or ceramic filter candles (for example, iron aluminide filter material).

The syngas in line 135 can have a heating value, corrected for heat losses and dilution effects, of about 1,863 kJ/m³ to about 2,794 kJ/m³; about 1,863 kJ/m³ to about 3,726 kJ/m³; about 1,863 kJ/m³ to about 4,098 kJ/m³; about 1,863 kJ/m³ to about 5,516 kJ/m³; about 1,863 kJ/m³ to about 6,707 kJ/³; about 1,863 kJ/m³ to about 7,452 kJ/m³; about 1,863 kJ/m³ to about 9,315 kJ/m³; or about 1,863 kJ/m³ to about 10,246 kJ/m³.

FIG. 2 depicts an illustrative gasifier system 200 for gasifying carbonaceous materials according to one or more embodiments. In one or more embodiments, the gasifier system 200 can include a mixer 205 and an air separation unit (“ASU”) 210. The gasifier system 200 can also include a gasifier that can include an oxidation zone 110, a gasification zone 115, a transfer line 120, and a separator 130, which can be the same or similar as discussed and described above in reference to FIG. 1. In one or more embodiments, a carbonaceous material introduced via line 202 and water via line 104 can be mixed or otherwise combined within the mixer 205 to provide a slurried mixture in line 102. The carbonaceous material and water in line 202 can be as discussed and described above with reference to FIG. 1.

The mixer 205 can be any device, system, or combination of systems and/or devices suitable for batch, intermittent, variable mixing rates, and/or continuous mixing of the carbonaceous material and water. In one or more embodiments, additives to stabilize the slurry to prevent settling of the solids can be added to the mixture. The mixer 205 can be capable of homogenizing immiscible fluids. Illustrative mixers 205 can include but are not limited to ejectors, inline static mixers, inline mechanical/power mixers, homogenizers, or combinations thereof.

The mixer 205 can operate at a temperature ranging from a low of about 5° C., about 15° C., or about 20° C. to a high of about 100° C., about 125° C. or about 150° C. The mixer 205 can operate at a pressure less than, equal to, or greater than the pressure of the gasification zone 115. In one or more embodiments, the mixer 205 can operate at a pressure ranging from a low of about 101 kPa, about 300 kPa, or about 600 kPa to a high of about 2,500 kPa, about 3,500 kPa, about 4,500 kPa or more.

In one or more embodiments, oxygen from the ASU 210 can be supplied via line 108 to the oxidation zone 110. The ASU 210 can provide a nitrogen free or essentially nitrogen-free and oxygen-rich oxidant via line 108 to the oxidation zone 110 thereby minimizing the nitrogen concentration in the system. The use of a nitrogen free or essentially-nitrogen free oxidant allows the gasifier 100 to provide a syngas via line 135 that is essentially nitrogen-free, e.g. containing less than about 5% mol, less than about 4% mol, less than about 3% mol, less than about 2% mol, less than about 1% mol, or less nitrogen/argon. In one or more embodiments, the ASU 210 can be a high-pressure, cryogenic type separator, which can be supplemented with air via line 207. The separated nitrogen can be removed from the ASU 210 via line 212. Although not shown, the separated nitrogen can be used to dry the carbonaceous material, added to a combustion turbine, as explained in more detail below or used as utility.

FIG. 3 depicts an illustrative gasification system 300 according to one or more embodiments. The gasification system 300 can include one or more gasifiers 300 which can be the same as or similar to the gasifier 100 and/or 200 discussed and described above with reference to FIGS. 1 and 2. The gasification system 300 can further include a heat exchanger 310, a particulate removal system 315 and gas purification system 325 to provide a syngas via line 329. In one or more embodiments, the gasification system 300 can include a CO₂ shift and/or recovery (“converter”) system 330 to convert at least a portion of any CO in the syngas in line 329. In one or more embodiments, the gasification system 300 can also include a gas converter system 340 to produce one or more Fischer-Tropsch products, chemicals, feedstocks, methane (“synthetic natural gas” or “SNG”), ammonia, methanol, derivatives thereof, and combinations thereof. In one or more embodiments, the gasification system 300 can also include a H₂ separator 350, fuel cell 360, combustor 365, gas turbine 370, steam turbine 390, heat recovery system 380, and generator (two are shown 375, 395) to produce fuel, power, steam and/or energy.

The syngas in line 135 can be as discussed and described above in reference to FIGS. 1 and 2. The syngas can be introduced to the heat exchanger 310 to provide a cooled syngas in line 311. Heat from the syngas can be indirectly or directly transferred to a heat transfer medium, such as boiler feed water, introduced via line 309. The steam or any other suitable heated heat transfer medium can be recovered via line 313. The particulate removal system 315 can partially or completely remove particulates from the cooled syngas in line 311 to provide separated particulates via line 317 and a particulate-lean syngas via line 319. Although not shown, the steam via line 313 can be introduced via line 106 to the gasifier 305, the heat recovery unit 390, the steam turbine 390, other process equipment, or combinations thereof.

Although not shown, in one or more embodiments, the one or more particulate removal systems 315 can optionally be used to partially or completely remove particulates from syngas in line 135 before cooling. For example, the syngas via line 135 can be introduced directly to the particulate removal system 315, resulting in hot gas particulate removal (e.g. from about 550° C. to about 1,050° C.). Although not shown, in one or more embodiments, two particulate removal systems 315 can be used, for example one particulate removal system 315 can be upstream of the heat exchanger 310 and one particulate removal system 315 can be downstream of the heat exchanger 310.

The one or more particulate removal systems 315 can include one or more separation devices such as conventional disengagers and/or cyclones (not shown). Particulate control devices (“PCD”) capable of providing an outlet particulate concentration below the detectable limit of about 0.1 ppmw can also be used. Illustrative PCDs can include but are not limited to, sintered metal filters, metal filter candles, and/or ceramic filter candles (for example, iron aluminide filter material).

The solid particulates via line 317 can be purged from the system, or recycled to the gasifier 305 (not shown). Although not shown, the separated syngas in line 319 can be further cooled using one or more heat exchangers. The syngas in line 319 can have a temperature of about 350° C. or less, such as about 150° C. to about 300° C.

The cooled, separated syngas in line 319 can be treated within one or more gas purification systems 325 to remove contaminants providing a waste gas via line 327 and a treated syngas via line 329. The one or more gas purification systems 325 can include any system, device, or combination of systems and/or devices suitable for removing sulfur and/or sulfur containing compounds from the treated syngas in line 329. Illustrative catalytic gas purification systems 325 can include, but are not limited to, systems using zinc titanate, zinc ferrite, tin oxide, zinc oxide, iron oxide, copper oxide, cerium oxide or mixtures thereof. Illustrative process-based gas purification systems 325 can include, but are not limited to, the Selexol™ process, the Rectisol® process, the CrystaSulf® process, and the Sulfinol® Gas Treatment Process.

One or more amine solvents such as methyl-diethanolamine (“MDEA”) can be used to remove any acid gas from the syngas in line 319. Physical solvents such as Selexol™ (dimethyl ethers of polyethylene glycol) or Rectisol® (cold methanol), can also be used. If the syngas in line 319 contains carbonyl sulfide (“COS”), the carbonyl sulfide can be converted by hydrolysis to hydrogen sulfide (“H₂S”) by reaction with water over a catalyst and then absorbed using the methods described above. If the syngas in line 319 contains mercury, the mercury can be removed using a bed of sulfur-impregnated activated carbon.

A cobalt-molybdenum (“Co—Mo”) catalyst can be incorporated into the one or more purification units 325 to perform a sour shift conversion of the syngas. The Co—Mo catalyst can operate at a temperature of about 290° C. in presence of H₂S, such as about 100 ppmw H₂S. If Co—Mo catalyst is used to perform a sour shift, subsequent downstream removal of sulfur can be accomplished using any of the above described sulfur removal methods and/or techniques.

In one or more embodiments, all or a portion of the treated syngas in line 329 can be introduced to one or more converters 330 to adjust the H₂ to CO ratio (H₂:CO) of the syngas by converting CO to CO₂. The converter 330 can also include a CO₂ recovery unit to separate at least a portion of the CO₂ from the converted syngas. The CO₂ present in the syngas introduced via line 329 and/or the converted syngas can be separated and/or recovered from the converter 330 via line 333 to provide a syngas via line 331 having a predetermined H₂:CO ratio. The desired H₂:CO ratio can depend upon the further downstream processing steps and/or uses, such as the synthesis of ammonia, methanol, and/or Fischer-Tropsch synthesis, fuel cells, power production, and the like.

Within the one or more shift converters, a water-gas shift reaction can react at least a portion of the CO in the treated syngas introduced via line 329 with water in the presence of a catalyst and/or a high temperature to produce H₂ and CO₂. The one or more shift converters can include, but are not limited to, single stage adiabatic fixed bed reactors; multiple-stage adiabatic fixed bed reactors with interstage cooling, steam generation or cold quench reactors; tubular fixed bed reactors with steam generation or cooling; fluidized bed reactors, or any combination thereof. A sorption enhanced water-gas shift (“SEWGS”) process, utilizing a pressure swing adsorption unit having multiple fixed bed reactors packed with shift catalyst and high temperature (around 475° C.) CO₂ adsorbent, can be used. Various shift catalysts can be employed. The converter 330 can also include a CO separator to separate at least a portion of the CO from the syngas in line 329. The separated CO can be used for the production of chemicals, such as acetic acid, phosgene/isocyanates, formic acid, and propionic acid.

The converter 330 can include one or more converters arranged in series, parallel, or a combination thereof. For example, a first converter (high temperature) can be operated at high temperature from about 300° C. to about 530° C. to convert a majority of the CO present in the treated syngas introduced via line 329 to CO₂ at a relatively high reaction rate using a catalyst. The catalyst can include, but is not limited to iron oxide, zinc ferrite, magnetite, chromium oxides, derivatives thereof, or any combination thereof A second reactor (low temperature) can be operated at a relatively low temperature of about 150° C. to about 300° C. to convert at least a portion of any remaining CO to CO₂ using a mixture of copper oxide and zinc oxide. The second reactor can use a catalyst that includes, but is not limited to copper, zinc, copper promoted chromium, derivatives thereof, or any combination thereof. A third converter operating at a temperature range between the first and second converters can replace the high temperature converter, the low temperature converter, both converters, or can be in addition to the two converters. The medium temperature converter can be operated at a temperature of from about 250° C. to about 350° C. The catalyst disposed in the medium temperature converter can include, but is not limited to, iron oxide, chromium oxide, derivatives thereof, or any combination thereof. Although not shown, in one or more embodiments the converter 330 can be upstream of the purifier 325.

The CO₂ recovery unit can use propylene carbonate, other alkyl carbonates, dimethyl ethers of polyethylene glycol of two to twelve glycol units (Selexol™ process), n-methyl-pyrrolidone, sulfolane, the Sulfinol® Gas Treatment Process, monoethanolamine (“MEA”), diethanolamine (“DEA”), triethanolamie (“TEA”), potassium carbonate, methyldiethanolamine (“MDEA”), diglycolamine (“DGA”), diisopropanolamine (“DIPA”), hydrophobic zeolites, derivatives thereof, mixtures thereof, or any combination thereof to separate at least a portion of the CO₂ from the syngas.

In one or more embodiments, the CO₂ recovered via line 333 can be used in a fuel recovery process to enhance the recovery of oil and gas. In an illustrative oil recovery process, CO₂ can be injected and flushed into an area beneath an existing well where “stranded” oil exists. The water and CO₂ removed with the crude oil can then be separated and recycled. In a similar process the CO₂ can be injected and flushed into an area beneath an existing gas well to increase the production of natural gas.

In one or more embodiments, the CO₂ recovered via line 333 can be captured and stored temporarily or permanently in order to reduce or eliminate the amount of CO₂ released into the atmosphere. In one or more embodiments, the CO₂ in line 333 can be injected into underground geological formations, such as depleted oil fields and/or gas fields, saline formations, unminable coal seams, saline-filled basalt formations, and the like. In one or more embodiments, the CO₂ in line 333 can be injected by ship, pipeline, or other suitable methods into a water column at depths of 1000 m or more, and the CO₂ can subsequently dissolve into the water. In one or more embodiments, the CO₂ in line 333 can be injected by ship, pipeline, or other suitable methods onto a the floor of a body of water, for example the sea floor, at depths greater than 3000 m, where the CO₂ is denser than water and can form a layer of CO₂ that can contain the CO₂ or at least delay dissolution of CO₂ into the environment. In one or more embodiments, the CO₂ in line 333 can be converted to carbonates, such as bicarbonates using limestone, or hydrates by reacting the CO₂ with metal oxides to produce stable carbonates.

In one or more embodiments, the CO₂ recovered via line 333 can undergo photosynthetic conversion to fix the CO₂ using biological organisms, such as bacteria or micro-algae under a controlled environment. The biological organism can use the natural process of photosynthesis to convert light, heat, and the CO₂ to useful products, such as carbohydrates, H₂, and oxygen.

In one or more embodiments, at least a portion of the treated syngas in line 331 can be recovered via line 339 and sold as a commodity. In one or more embodiments, at least a portion of the converted syngas via line 331 can be introduced to the gas converter 340 to produce one or more products. For example, the gas converter 340 can include, but is not limited to a Fischer-Tropsch synthesis unit to provide one or more Fischer-Tropsch (“F-T”) products that can include, but are not limited to refinery/petrochemical feedstocks, transportation fuels, synthetic crude oil, liquid fuels, lubricants, alpha olefins, waxes, and the like. The reaction can be carried out in any type reactor, e.g., fixed bed, moving bed, fluidized bed, slurry, bubbling bed, etc. using copper, ruthenium, iron or cobalt based catalysts, or combinations thereof, under conditions ranging from about 190° C. to about 450° C. depending on the reactor configuration. Additional reaction and catalyst details can be found in U.S. Patent Application No. 20050284797 and U.S. Pat. Nos. 5,621,155; 6,682,711; 6,331,575; 6,313,062; 6,284,807; 6,136,868; 4,568,663; 4,663,305; 5,348,982; 6,319,960; 6,124,367; 6,087,405; 5,945,459; 4,992,406; 6,117,814; 5,545,674 and 6,300,268.

The F-T products can be liquids which can be shipped to a refinery site for further chemically reacting and upgrading to a variety of products. Certain products, e.g. C₄-C₅ hydrocarbons, can be high quality paraffin solvents which, if desired, can be hydrotreated to remove olefin impurities, or employed without hydrotreating to produce a wide variety of wax products. Hydrocarbons, including C₁₆ and higher compounds can be upgraded by various hydroconversion reactions, e.g., hydrocracking, hydroisomerization catalytic dewaxing, isodewaxing, or combinations thereof, to produce mid-distillates, diesel fuels, jet fuels, isoparaffinic solvents, lubricants, drilling oils suitable for use in drilling muds, technical and medicinal grade white oil, chemical raw materials, and various specialty products.

At least one of the one or more gas converters 340 can include one or more slurry bubble column reactors to produce one or more F-T products. The slurry bubble column reactors can operate at a temperature of less than 225° C. and from a vacuum to about 4,140 kPa, or about 1,720 kPa to about 2,410 kPa using a cobalt catalyst promoted with rhenium and supported on titania having a Re:Co weight ratio in the range of about 0.01 to about 1 and containing from about 2% by weight to about 50% by weight cobalt. The catalyst within the slurry bubble column reactors can include, but is not limited to, a titania support impregnated with a salt of a catalytic copper or an Iron Group metal, a polyol or polyhydric alcohol and, optionally, a rhenium compound or salt. Examples of polyols or polyhydric alcohols include glycol, glycerol, derythritol, threitol, ribitol arabinitol, xylitol, allitol, dulcitol, gluciotol, sorbitol, and mannitol. The catalytic metal, copper or Iron Group metal as a concentrated aqueous salt solution, for example cobalt nitrate or cobalt acetate, can be combined with the polyol and optionally perrhenic acid while adjusting the amount of water to obtain 15% by weight cobalt in the solution and using optionally incipient wetness techniques to impregnate the catalyst onto rutile or anatase titania support, optionally spray-dried and calcined. This method reduces the need for rhenium promoter. Additional details can be found in U.S. Pat. Nos. 5,075,269 and 6,331,575.

In one or more embodiments, at least one of the one or more gas converters 340 can be used to produce SNG, methanol, alkyl formates, dimethyl ether, ammonia, acetic anhydride, acetic acid, methyl acetate, acetate esters, vinyl acetate and polymers, ketenes, formaldehyde, dimethyl ether, olefins, urea, derivatives thereof, and/or combinations thereof. For methanol production, for example, the Liquid Phase Methanol Process can be used (LPMEOH™). In this process, the CO in the syngas in line 412 can be directly converted into methanol using a slurry bubble column reactor and catalyst in an inert hydrocarbon oil reaction medium which can conserve heat of reaction while idling during off-peak periods for a substantial amount of time while maintaining good catalyst activity. Additional details can be found in U.S. patent application Ser. No. 11/311,766 and prior published Heydorn, E. C., Street, B. T., and Kornosky, R. M., “Liquid Phase Methanol (LPMEOH™) Project Operational Experience,” (Presented at the Gasification Technology Council Meeting in San Francisco on Oct. 4-7, 1998). Gas phase processes for producing methanol can also be used. For example, known processes using copper based catalysts, the Imperial Chemical Industries process, the Lurgi process, and the Mitsubishi process can be used.

For ammonia production, at least one of the one or more gas converters 340 can be adapted to operate the Haber-Bosch process described in LeBanc et al in “Ammonia,” Kirk-Othmer Encyclopedia of Chemical Technology, Volume 2, 3rd Edition, 1978, pp., 494-500. For alkyl formate production, such as for example, methyl formate, any of several processes wherein CO and methanol are reacted in either the liquid or gaseous phase in the presence of an alkaline catalyst or alkali or alkaline earth metal methoxide catalyst can be used. Additional details can be found in U.S. Pat. Nos. 3,716,619; 3,816,513; and 4,216,339.

Although not shown, in one or more embodiments, at least a portion of the converted syngas via line 343 can be sold or upgraded using further downstream processes. In one or more embodiments, at least a portion of the treated syngas in line 331 can bypass the one or more gas converters 340 described above, and can be fed directly to the H₂ separator 350 via line 347.

The one or more H₂ separators 350 can include any system, device, or combination of systems and/or devices suitable for selectively separating H₂ from syngas to provide one or more purified H₂ products via line 353 and one or more waste effluents via line 351. For example, the H₂ separator 350 can utilize pressure swing absorption, cryogenic distillation, and semi-permeable membranes. Suitable absorbents can include caustic soda, potassium carbonate or other inorganic bases, and/or alanolamines.

In one or more embodiments, the converter 330 can provide a syngas via line 331 that includes the CO₂, e.g. there is not a CO₂ removal system in the converter system 330. If the CO₂ remains in the syngas in line 331 the H₂ separator 350 can separate at least a portion of the CO₂ from the converted syngas to provide CO₂ via line 351, and a H₂ product via line 353. The CO₂ via line 351 can include CO, argon, nitrogen, and other components that can be separated from the syngas along with the CO₂ or in the absence of CO₂ in the H₂ separator 350.

In one or more embodiments, all or a portion of the H₂ product via line 353 can be used to supply one or more fuel cells 360, and/or all or a portion can be combined with the treated syngas in line 331 prior to use as a fuel in the one or more combustors 365. Although not shown, the H₂ product in line 353 can be recovered and used for other processes, such as upgrading other hydrocarbons in hydrodealkylation, hydrodesulfurization, hydrocracking, H₂ation and other hydroprocesses; as a reducing agent for metallic ores, for atomic H₂ welding, coolant, and other uses.

In one or more embodiments, all or a portion of the converted syngas in line 331 and/or the H₂ in line 353 can be combusted in one or more combustors 365 to provide a high pressure/high temperature exhaust gas via line 367. Air or other suitable oxidant via line 363 can be introduced to the one or more combustors 365. The exhaust gas via line 367 can be introduced to one or more gas turbines 370 to provide an exhaust gas via line 373 and mechanical shaft power to drive the one or more electric generators 375. The exhaust gas via line 373 can be introduced to the heat recovery system 380 to provide steam via line 106.

The heat recovery system 380 can be a closed-loop heating system, e.g. a waste heat boiler, shell-and-tube heat exchanger, and the like, capable of exchanging heat between the exhaust gas introduced via line 373 and boiler feed water and/or steam introduced via line 397 to produce the steam via line 106. The heat recovery system 380 can provide up to 10,350 kPa and 550° C. superheat/reheat steam via line 106 without supplemental fuel.

In one or more embodiments, at least a portion of the steam via line 106 can be introduced to the steam turbine 390 to provide mechanical shaft power to drive one or more electric generators 395. In one or more embodiments, at least a portion of the steam via line 106 can be introduced to the gasifier 100, and/or other auxiliary process equipment (not shown). Lower pressure steam from the steam turbine 390 can be recycled to the one or more heat recovery systems 380 via line 397. The steam via line 106 can be introduced to one or more steam turbines 390, heat recovery systems 380, gasifiers 100, or any combination thereof. The residual heat from the steam in line 397 can be rejected to a condensation system or sold to local steam consumers (not shown).

FIG. 4 depicts another illustrative gasification system 400 according to one or more embodiments. In one or more embodiments, the gasification system 400 can include one or more integrated combustion turbines 410 to further enhance efficiency. In one or more embodiments, the gasification system 400 can include an ASU 425 to provide an oxygen enriched oxidant via line 108 to the gasifier 100. The gasifier 100, heat exchanger 310, particulate removal system 315, gas purification system 325, converter system 330, gas converter 340, H₂ separator 350, steam turbine 390, heat recovery system 380, generators 375, 395, and air separation unit 425 can be the same or similar as discussed and described above with reference to FIGS. 1-3.

In one or more embodiments, at least a portion the syngas via line 331 and/or at least a portion of the H₂ via line 353 can be used as a fuel for one or more combustion turbines 410. The combustion turbine 410 can produce a high temperature exhaust gas and shaft power to drive the one or more generators 375. Heat from the combustion turbine exhaust gas via line 373 (generally about 600° C.) can be recovered using the heat recovery system 380 to generate steam via line 106 for subsequent use in the steam turbine 390, the gasifier 100, and/or other processes.

Ambient air via line 402 can be compressed using the combustion turbine 410 to provide compressed air via line 412 directly to the gasifier 100 and/or ASU 425. Nitrogen separated within the ASU 425 can be purged and/or returned to the one or more combustion turbines 410 via line 427 to reduce nitrogen oxide emissions by lowering the combustion temperature in the combustion turbine. The nitrogen acts as a diluent with no heating value, i.e. a heat sink. To further minimize nitrogen oxides formation, the syngas via line 331 entering the combustion turbine 410 can be saturated with water (not shown).

Pure oxygen, nearly pure oxygen, essentially oxygen, and/or oxygen-enriched air from the ASU 425 can be supplied to the gasifier 100 via line 108. The ASU 425 can provide a nitrogen-lean and oxygen-rich feed via line 108 to the gasifier 305, thereby minimizing the nitrogen concentration in the syngas provided via line 135. The use of a pure or nearly pure oxygen feed allows the gasifier 305 to produce a syngas via line 135 that can be essentially nitrogen-free. The ASU 425 can be the same or similar to the ASU discussed and described above in reference to FIG. 2. The ASU 425 can be a high-pressure, cryogenic type separator. Air can be introduced to the ASU 425 via line 416. The separated nitrogen via line 427 from the ASU 425 can be added to the combustion turbine 410 or used as utility. The ASU 425 can provide from about 10%, about 30%, about 50%, about 70%, about 90%, or about 100% of the total oxidant fed to the gasifier 305 via line 108.

EXAMPLES

Embodiments of the present invention can be further described with reference to the following simulated examples. Table 1 summarizes the basic process conditions for various fees: a dry feed, i.e. no water added to the carbonaceous material; a 55% wt; a 62% wt; and a 70% wt carbonaceous material slurried with water, where water constitutes the balance of the mixture. Tables 2 and 3 illustrate the increase in CO₂ and the decrease in CO as the water content is increased relative to a non-slurried process using air as the oxidant (Table 1) and oxygen as the oxidant (Table 2), according to one or more embodiments described above with reference to FIGS. 1-4.

TABLE 1 Process Conditions 70% wt 62% wt 55% wt Carbo- Carbo- Carbo- naceous naceous naceous Dry Feed material material material Air/Coal Ratio 2.86 3.10 3.22 3.36 Gasifier Temp ° C. 982 982 982 982 Gasifier Pressure kPa 3,600 3,600 3,600 3,600 HP Steam 1.00 1.22 1.32 1.43

As shown in Table 1, the temperature of the gasifier is maintained at 982° C. and the pressure is maintained at 3,600 kPa. As the amount of water added to the mixture increases more oxidant, which is air as shown, is required to be introduced via line 108 to the gasifier 100 as shown in FIG. 1, for example. The additional oxidant is necessary to provide the additional heat required to gasify the slurried mixture. The additional high pressure steam that can be generated in the heat exchanger 310, see FIG. 1 for example, increases by 22% for a 30% wt water mixture, 32% for a 38% wt water mixture, and 43% wt for a 45% water mixture. The additional steam generated can be used to generate additional power, for example the steam can be introduced via line 313 to the steam turbine 390 to provide power via generator 395 or other suitable uses on site or off site.

TABLE 2 Air as the Oxidant Dry 70% Slurry Feed 62% Slurry Feed 55% Slurry Feed Feed HT LT HT LT HT LT Gasifier Gasifier Shift Shift Gasifier Shift Shift Gasifier Shift Shift Mole Frac Exit Exit Outlet Out Exit Outlet Out Exit Outlet Out CH₄ 0.021 0.015 0.015 0.015 0.013 0.013 0.013 0.012 0.012 0.012 CO 0.222 0.148 0.077 0.053 0.124 0.051 0.027 0.103 0.034 0.015 CO₂ 0.070 0.103 0.173 0.197 0.110 0.183 0.206 0.115 0.184 0.203 H₂ 0.110 0.127 0.198 0.222 0.126 0.199 0.222 0.123 0.191 0.210 H₂O 0.052 0.127 0.056 0.032 0.162 0.090 0.066 0.199 0.130 0.111 N₂ 0.521 0.472 0.472 0.472 0.456 0.456 0.456 0.441 0.441 0.441

As shown in Table 2, a dry carbonaceous material, that is no water is added to the carbonaceous material, provides a syngas, using air as the oxidant, at the gasifier outlet containing about 7% mol CO₂ and about 22% mol CO. For a slurried mixture that contains about 30% wt water the CO₂ content in the syngas at the gasifier outlet increases to about 10% mol and the CO decreases to about 15% mol. The addition of more water, e.g. 38% wt and 45% wt, produces a syngas containing about 11% CO₂ and about 12.5% CO and about 10% CO and about 11.5% CO₂, respectively. The increased production of CO₂ in the gasifier can reduce or eliminate the need for CO₂ shift converters downstream, depending upon the particular use of the syngas. Additionally, the amount of H₂ production is increased from about 11% mol using a dry carbonaceous material to about 12.3% by adding about 45% wt water to the carbonaceous material and the methane content in the syngas at the gasifier outlet is reduced by almost 50% from about 2.1% mol to about 1.2% mol.

TABLE 3 Oxygen as the Oxidant Dry 70% Slurry Feed 62% Slurry Feed 55% Slurry Feed Feed HT LT HT LT HT LT Gasifier Gasifier Shift Shift Gasifier Shift Shift Gasifier Shift Shift Mole Frac Exit Exit Outlet Out Exit Outlet Out Exit Outlet Out CH₄ 0.044 0.029 0.029 0.029 0.024 0.024 0.024 0.022 0.022 0.022 CO 0.467 0.285 0.148 0.102 0.232 0.095 0.050 0.186 0.062 0.027 CO₂ 0.147 0.198 0.333 0.379 0.206 0.341 0.386 0.208 0.334 0.368 H₂ 0.231 0.244 0.381 0.428 0.235 0.371 0.416 0.223 0.347 0.381 H₂O 0.109 0.244 0.108 0.062 0.303 0.168 0.123 0.360 0.236 0.201 N₂ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

As shown in Table 3, a dry carbonaceous material produces a syngas using oxygen as the oxidant at the gasifier outlet containing about 15% mol CO₂ and about 47% mol CO. For a slurried mixture that contains about 30% wt water the CO₂ content in the syngas at the gasifier outlet increases to about 20% mol and the CO decreases to about 29% mol. The addition of more water, e.g. 38% wt and 45% wt, produces a syngas containing about 21% mol CO₂ and about 23% mol CO and about 21% mol CO₂ and about 19% mol CO, respectively.

Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

Various terms have been defined above. To the extent a term used in a claim is not defined above, the term should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

1) A method for processing a carbonaceous material comprising: mixing a carbonaceous material and water to provide a slurried mixture, wherein the water is at least 90% liquid phase; gasifying at least a portion of the slurried mixture in the presence of a combustion gas to provide carbonaceous solids and a syngas comprising hydrogen, carbon monoxide, and carbon dioxide, wherein the syngas is at a temperature of from about 400° C. to about 1,650° C.; selectively separating at least a portion of the carbonaceous solids from the syngas to provide a syngas product and carbonaceous solids; and combusting at least a portion of the separated carbonaceous solids in the presence of an oxidant to provide at least a portion of the combustion gas. 2) The method of claim 1, further comprising converting at least a portion of the carbon monoxide in the syngas product to carbon dioxide. 3) The method of claim 1, further comprising separating at least a portion of the carbon dioxide from the syngas product, and storing the separated carbon dioxide in a geological formation, a body of water, or both. 4) The method of claim 3, further comprising converting at least a portion of the carbon monoxide in the syngas product to carbon dioxide prior to separating at least a portion of the carbon dioxide from the syngas. 5) The method of claim 1, further comprising separating at least a portion of the carbon dioxide from the syngas product, and converting at least a portion of the separated carbon dioxide to a carbonate, a carbohydrate, or both. 6) The method of claim 5, further comprising converting at least a portion of the carbon monoxide in the syngas product to carbon dioxide prior to separating at least a portion of the carbon dioxide from the syngas. 7) The method of claim 1, further comprising directly or indirectly transferring heat from the syngas product to water, steam, or both to provide a cooled syngas product and a steam product. 8) The method of claim 1, wherein the water concentration of the slurried mixture ranges from about 20% wt to about 70% wt. 9) The method of claim 1, wherein the oxidant comprises air and the syngas comprises less than 20% mol carbon monoxide and at least 8% mol carbon dioxide. 10) The method of claim 1, wherein the oxidant is essentially nitrogen-free and the syngas comprises less than 40% mol carbon monoxide and at least 16% mol carbon dioxide. 11) The method of claim 1, wherein the amount of oxidant present is from about 1% to about 60% of the stoichiometric oxygen required to oxidize the total amount of carbonaceous solids. 12) A method for processing a carbonaceous material comprising: combining a carbonaceous material and water in a mixing zone to provide a slurried mixture, wherein the water is at least 90% liquid phase; gasifying a portion of the slurried mixture in the presence of a combustion gas in a gasification zone to provide carbonaceous solids and a syngas comprising hydrogen, carbon monoxide, and carbon dioxide, wherein the syngas has a temperature of from about 400° C. to about 1,650° C.; selectively separating at least a portion of the carbonaceous solids from the syngas in a separation zone to provide a syngas product and carbonaceous solids; and combusting at least a portion of the carbonaceous solids in the presence of an oxidant in a combustion zone to provide at least a portion of the combustion gas. 13) The method of claim 12, further comprising separating at least a portion of the carbon dioxide from the syngas product, and storing the removed carbon dioxide in a geological formation, a body of water, as a carbonate compound, or any combination thereof. 14) The method of claim 13, further comprising converting at least a portion of the carbon monoxide in the syngas product to carbon dioxide prior to separating the carbon dioxide. 15) The method of claim 12, wherein the water concentration of the slurried mixture ranges from about 20% wt to about 70% wt. 16) The method of claim 12, wherein the oxidant comprises air and the syngas comprises less than 20% mol carbon monoxide and at least 8% mol carbon dioxide. 17) The method of claim 12, wherein the oxidant is essentially nitrogen-free and the syngas comprises less than 40% mol carbon monoxide and at least 16% mol carbon dioxide. 18) The method of claim 12, further comprising directly or indirectly transferring heat from the syngas product to water, steam, or both to provide a cooled syngas product and a steam product. 19) A system for processing a carbonaceous material comprising: a gasification zone adapted to gasify a carbonaceous material and water mixture in the presence of a combustion gas to provide carbonaceous solids and a syngas comprising hydrogen, carbon monoxide, and carbon dioxide, wherein the water is at least 90% liquid phase; a separator in fluid communication with the gasification zone adapted to separate at least a portion of the carbonaceous solids from the syngas; and an oxidation zone in fluid communication with the gasification zone adapted to combust at least a portion of the separated carbonaceous solids to provide at least a portion of the combustion gas. 20) The system of claim 19, further comprising a separator adapted to separate at least a portion of the carbon dioxide from the syngas to provide a syngas product comprising less than about 1% mol carbon dioxide, wherein the separated carbon dioxide is suitable for storage in a geological formation, a body of water, as a carbonate compound, or any combination thereof. 